1. Technical Field
This disclosure relates to sensing systems and more particularly, to a system for sensing relative amounts of constituents present in a multiphase liquid/gas mixture.
2. Description of the Related Art
It is recognized that multiphase liquid gas/mixtures occur naturally, as in the liquid, which emerges from wellheads at oil production fields. Such mixtures are, at the present time, separated so that the relative percentage of each may be determined. The result of this determination may be a change in the way a well is developed, or in the way that the products of such wells, in areas of mutual development, are managed, especially where use of common product pipe transmission may be desired.
Under such circumstances, it is highly desirable to measure not only the total flow rate of such a multiphase liquid, but also to accurately determine how much of each constituent may be present in the mixture delivered. As oil emerges from a well head, the oil frequently includes both gas and water. Water is usually injected from the surface to drive the oil to the well. It is important to know the percentage of oil, gas and water on a real time basis to assure that the well is operating efficiently, or if it is necessary to take action to improve its efficiency. However, it is difficult to measure such a multiphase liquid to determine the relative percentages flowing at a given time, or even over a given period of time.
In the production of oil, it is frequently found that natural gas resides in the same strata as the oil, which is being produced. When such wells are on land, it is economical to separate the gas from the oil, and then store, transport, treat and market the gas as well as the oil. However, when such a well is offshore, the storage space for the gas is usually not available, and it would be necessary to install an expensive pipeline from the offshore well to a land based storage facility.
In addition, when the pressure of the well is low, it is necessary to pump water, or other chemicals down to the well to force the oil to the surface. Accordingly, what comes up is frequently a mixture of oil, gas and water, in variable proportions. To judge the performance of the well, it is necessary to know these proportions, and thus enable the operators to xe2x80x9ctreatxe2x80x9d the well to enhance its performance. For this and other reasons, such as evaluating the relative performance of different wells, it is desired to measure the flow rate of the multiphase gas/liquid, and determine the proportions of each component.
At present there are such instruments to measure multiphase flows. In general, they operate by a combination of means, such as various types of flow meters, such as turbine, capacitive correlation flow meters and dielectric constant sensors, various conventional mechanical flow meters, and radioactive density sensing devices. Unfortunately, such instruments are extremely expensive, ranging in price from about $200,000 to several million, not including the expense of installation at the wellhead.
Therefore, a need exists for an apparatus to perform the measurement of amounts of multiphase fluids in a multiphase flow. A further need exists for providing an easily and economically implemented way of providing multiphase flow measurements, which does not disrupt the flow of the multiphase fluid.
A non-intrusive flowmeter for measurement of a multiphase liquid in a pipeline is disclosed. The present invention may operate as both a flowmeter and as a means of determining the relative quantity of constituent materials in a flow, for example, Oil, Water and Gas flowing in a pipe. The present invention employs the ability of a Wide Beam Clamp-On Ultrasonic flowmeter to operate at high levels of aeration and non-homogeneity of the flow. In addition, this type of flowmeter is capable of analyzing the received sonic data to identify the relative amount of constituents, e.g., gas and water in oil, by the effect that these components have on the sonic properties of the medium, and by the effect on the received signal amplitude.
A method for determining constituent fluids for a multiphase flow in a pipe is provided by mounting two transducers on a pipewall. The first and second transducers are longitudinally offset in a longitudinal direction parallel to the flow. A first sonic wave is generated through the pipewall and is split into a pipewall wave and a transverse wave. The pipewall wave travels in the pipewall directly between the transducers, and the transverse wave is reflected through the flow between the transducers. With knowledge of one of the fluids in the flow, attenuation is measured of the transverse wave relative to the pipewall wave to determine proportions of constituent liquids in the flow. Amplitude fluctuations are determined in the transverse wave relative to the pipewall wave, and based on the amplitude fluctuations, proportions of gas bubbles in the flow are determined.
These and other objects, features and advantages of the present invention will be come apparent from the following detailed description of illustrative embodiments thereof, which is to be read in connection with the accompanying drawings.